Fractured Production Wells Research Articles

Interplay between Viscous Pressure and Capillary Pressure on Polymer Gel Dehydration and Water Shutoff in Hydraulically Fractured Reservoirs

Hydraulic fracturing is essential for efficient developments of low-permeability reservoirs. For these fractured production wells, serious water channeling frequently occurs because of the fracture...

Role of Stress Reorientation in the Success of Refracture Treatments in Tight Gas Sands

Summary The redistribution of stresses around a fractured vertical well has two sources: opening of propped fracture (mechanical effects) and production or injection of fluids in the reservoir (poroelastic effects). In this paper, the coupling of both phenomena was numerically modeled to quantify the extent of stress reorientation around fractured production wells. The results have been compared to field data from the Codell tight gas formation and analyzed for their impact on refracturing operations. For previously fractured wells, a secondary fracture may be initiated perpendicular to the first fracture if a stress-reversal region is present. Altered-stress refracturing makes it possible to access zones of the reservoirs that are less depleted, thus increasing well production and reserves. The results of our model quantitatively agree with previous tiltmeter measurements, confirming the existence of refracture reorientation in the Codell formation. The performance of refracturing treatments has been observed to be highly variable in the Wattenberg field (Colorado), with some wells underperforming while others are restored to initial production rates. Historical production from neighboring wells and initial fracture performance were shown to impact the potential benefits from refracturing predicted by the numerical model. This paper introduces a 3D model, coupling mechanical and poroelastic stress reorientation used to interpret tiltmeter measurements and historical production in the Codell tight gas formation. Guidelines are drawn from the Wattenberg field case study that allow an operator to select candidate wells, choose the timing of the refracture operation in the life of the well, and evaluate the potential increase in well production after refracturing.

Quantifying Transient Effects in Altered-Stress Refracturing of Vertical Wells

Summary The production or injection of fluids in reservoirs results in a redistribution of stresses. In this paper, the extent of stress reorientation has been calculated for fractured production and injection wells and the results have been analyzed for their effect on refracturing operations. Rules of thumb and charts have been provided to help with candidate-well selection for refracturing on the basis of the study. For previously fractured wells, it is possible to create a secondary fracture that is perpendicular to the first. The secondary orthogonal fracture can be created only within a certain time window that, in turn, depends on the reservoir properties. Conditions leading to orthogonal secondary fractures in different kinds of reservoirs (oil, gas, and tight gas reservoirs) have been analyzed to establish some rules of thumb. The effects of the layers bounding the pay zone and of permeability heterogeneity and anisotropy on stress reorientation are also discussed. Our results allow us to quantify the phenomenon of orthogonal secondary fracturing around fractured production wells by calculating the extent of the stress-reversal region as a function of time. The results of our model are shown to agree qualitatively with field observations obtained from microseismic measurements. The model presented in the study helps to clarify the concept of refracturing and provides a quantitative estimate of the time window for refracturing as a function of dimensionless parameters. The final result demonstrates the potential of the model to increase the reservoir sweep in unconventional reservoirs for which the optimum time window for refracturing is on the order of months to years. The conclusions of this study are useful for the design of refracturing operations and for candidate-well selection.

Characterization of Partially Formed Polymer Gels for Application to Fractured Production Wells for Water-Shutoff Purposes

Summary A laboratory study characterized partially formed chromium(III)-carboxylate/acrylamide-polymer (CC/AP) gels for water shutoff in fractures. These partially formed gels showed much lower effective viscosities during placement than comparable fully formed gels. During placement, leakoff rates through fracture faces were low for gelants and partially formed gels. During the first brine injection after gel placement, the pressure gradient required to breach the gel increased with the increasing polymer concentration. Most gel remained in the fracture and did not wash out. During brine flow through "wormholes" in the gel, stabilized residual-resistance factors (Frr) were large and increased with increasing polymer concentration.

Polymer Gels Formulated With a Combination of High-and Low-Molecular-Weight Polymers Provide Improved Performance for Water-Shutoff Treatments of Fractured Production Wells

SummaryA laboratory study has shown improved performance for fracture-problem water-shutoff polymer gels that are formulated with a combination of high-and low-molecular-weight (MW) polymers. These gels are intended for application to fractures or other high-permeability anomalies that are in direct contact with petroleum production wells. More specifically, we focused on evaluating the mechanical strength and improved performance of these water-shutoff gels for use when exceptionally large fracture apertures or large drawdown pressures are encountered. During our study, the gels were injected into laboratory-scale fractures while the gel was in a partially formed state. The flooding-experiment study involved the placement of partially formed chromium(III)carboxylate/acrylamide-polymer (CC/AP) gels in 1-to 4-mm (0.04-to 0.16-in.) apertures, by 2-ft-long × 1.5-in.-height fractures where the fracture walls were 700-md unfired Berea sandstone.During the injection of a 1.5% high-MW and 2.0% low-MW polymer-gel formulation, the partially formed gel fluid exhibited an effective viscosity of approximately 500 cp during placement in a 1-mm (0.04-in.) -aperture fracture, and the matured gel exhibited exceptionally good fracture-plugging characteristics. The gel withstood 52-psi total differential pressure across the fracture length (26-psi/ft pressure gradient) for 24 hours, while permitting no detectable brine flow through the gel-filled fracture. Subsequently, when the differential pressure was increased to 175 psi (88-psi/ft pressure gradient), the gel rendered a brine permeability-reduction factor in the fracture of 30,000. When placed in a 4-mm (0.16-in.)aperture fracture, a 25-psi/ft critical pressure gradient was required to render first and limited brine flow through the fracture containing gel of the same composition. After exceeding the critical pressure gradient, the stabilized permeability-reduction factor imparted by the gel to brine flow in the fracture was 260,000. When increasing the brine flow rate through a gel-containing 4-mm fracture from 500 to 8,000 cm3/hr (superficial velocities of 260 to 4,100 ft/d in the open fracture), the stabilized permeability-reduction factor decreased from 100,000 to 39,000.The high-and low-MW CC/AP gels exhibited disproportionate permeability-reduction (DPR) effects during oil and brine flow through gel-filled fractures. However, the gels of this study are probably better characterized as total-shutoff or sealing agents (not DPR agents) because of the large permeability reduction imparted to oil flow through the gel-filled fractures.

Integrated Downhole Monitoring of Hydraulically Fractured Production Wells

This article is a synopsis of paper SPE 65156,"Integrated Downhole Monitoring of Hydraulically Fractured Production Wells," by Matt Bell, SPE, and Hans Kraaijevanger, SPE, Petroleum Development Oman LLC, and Christophe Maisons, Magnitude, originally presented at the 2000 SPE European Petroleum Conference, Paris, 24-25 October.

Sizing Gelant Treatments in Hydraulically Fractured Production Wells

Summary Often, when production wells are stimulated by hydraulic fracturing, the fracture unintentionally breaks into water zones causing substantially increased water production. To correct this problem, we developed an engineering basis for designing and sizing gelant treatments in hydraulically fractured production wells. In these treatments, gelant penetrates a short distance from the fracture face into the porous rock associated with both water and hydrocarbon zones. Success for a given treatment requires that the gel reduce permeability to water much more than that to hydrocarbon. We present a simple 11-step procedure for sizing these gelant treatments. This procedure was incorporated in user-friendly graphicaluser-interface software that can be downloaded from our web site at http://baervan.nmt.edu/ResSweepEffic/reservoir.htm.